The recovery of hydrocarbons from subterranean zones relies on the process of drilling wellbores. The process includes drilling equipment situated at surface and a drill string extending from the surface equipment to the formation or subterranean zone of interest. The drill string can extend thousands of meters below the surface. The terminal end of the drill string includes a drill bit for drilling (or extending) the wellbore. In addition to this conventional drilling equipment the system also relies on some sort of drilling fluid, which in most cases is a drilling “mud” which is pumped through the inside of the drill string. The drilling mud cools and lubricates the drill bit and then exits out of the drill bit and carries rock cuttings back to surface. The mud also helps control bottom hole pressure and prevents hydrocarbon influx from the formation into the wellbore, which can potentially cause a blow out at surface.
Directional drilling is the process of steering a well away from vertical to intersect a target endpoint or follow a prescribed path. At the terminal end of the drill string is a bottom-hole-assembly (“BHA”) which comprises 1) a drill bit; 2) a steerable downhole mud motor of rotary steerable system; 3) sensors of survey equipment (logging-while-drilling (LWD) and/or measurement-while-drilling (MWD)) to evaluate downhole conditions as well depth progresses; 4) equipment for telemetry of data to surface; and 5) other control mechanisms such as stabilizers or heavy weight drill collars. The BHA is conveyed into the wellbore by a metallic tubular.
MWD equipment is used to provide downhole sensor and status information to surface in a near real time mode while drilling. This information is used by the rig crew to make decisions about controlling and steering the well to optimize drilling speed and trajectory based on numerous factors including lease boundaries, location of existing wells, formation properties, and hydrocarbon size and location. This can include making intentional deviations from an originally-planned wellbore path as necessary based on information gathered from the downhole sensors during the drilling process. The ability to obtain real time data during MWD results in a relatively more cost effective and efficient drilling operation.
Known MWD tools contain essentially the same sensor package to survey the wellbore, however the data may be sent back to surface by various telemetry methods. Such telemetry methods include, but are not limited to the use of a hardwired drill pipe, acoustic telemetry, use of a fibre optic cable, mud pulse (MP) telemetry and electromagnetic (EM) telemetry. The sensors are usually located in an electronics probe or instrumentation assembly contained in a cylindrical cover or housing located near the drill bit.
MP telemetry involves creating pressure waves in the drilling mud circulating inside the drill string. Mud circulates from surface to downhole using positive displacement pumps. The resulting flow rate of mud is typically constant. Pressure pulses are generated by changing the flow area and/or flow path of the drilling mud as it passes the MWD tool in a timed, coded sequence, thereby creating pressure differentials in the drilling mud. The pressure pulses act to transmit data utilizing a number of encoding schemes. These schemes may include amplitude shift keying (ASK), frequency shift keying (FSK), phase shift keying (PSK), or a combination of these techniques.
The pressure differentials or pulses may be either negative pulses or positive pulses. Valves that open and close a bypass mud stream from inside the drill pipe to the wellbore annulus create a negative pressure pulse. All negative pulsing valves need a high differential pressure below the valve to create a sufficient pressure drop when the valve is open, which results in negative valves being more prone to washing. With each actuation, the valve hits against the valve seat to ensure it completely closes the bypass; this impact can lead to mechanical and abrasive wear and failure. Valves that use a controlled restriction within the circulating mud stream create a positive pressure pulse. Some positive pulsing valves are hydraulically powered to reduce the required actuation power and typically have a main valve indirectly operated by a pilot valve. The pilot valve closes a flow restriction which actuates the main valve to create a pressure pulse. Pulse frequency is typically governed by pulse generating motor speed changes. The pulse generating motor requires electrical connectivity with other elements of the MWD probe such as a battery stack and sensors.
A number of different types of valves are currently used to create positive pressure pulses. Generally, pressure pulse valves are capable of generating discrete pulses at a predetermined frequency by selective restriction of the mud flow. In a typical rotary or rotating disc valve pulser, a control circuit activates a motor (e.g. a brushless or DC electric motor) that rotates a windowed restrictor (rotor) relative to a fixed housing (stator). As the rotor rotates it moves between an open position where the window is fully open and a closed position where the window is partially restricted to produce pressure pulses in the drilling mud flowing through the rotor. The rotor is rotated either continuously in one direction (mud siren), incrementally by oscillating the rotor in one direction and then back to its original position, or incrementally in one direction only. Rotary pulsers are typically actuated by means of a torsional force applicator which rotates the rotor a short angular distance to either the open or closed position, with the rotor returning to its start position in each case. Motor speed changes are required to change the pressure pulse frequency.
Various parameters can affect the mud pulse signal strength and rate of attenuation such as original signal strength, carrier frequency, depth between surface transducer and downhole modulator, internal diameter of the drill pipe, density and viscosity of the drilling mud, volumetric flow rate of drilling mud, and flow area of the rotor window. Rotary valve pulsers require an axial gap between the stator and rotor to provide a flow area for drilling mud, even when the valve is in the “closed” position. As a result the rotary pulser is never completely closed as there must be some flow of drilling mud for satisfactory drilling operations to be conducted. The size of the gap is dictated by previously mentioned parameters. A skilled technician is required to set the correct gap size and to calibrate the pulser.
U.S. Pat. No. 8,251,160, issued Aug. 28, 2012, (incorporated herein by reference) discloses an example of a MP apparatus and method of using same. It highlights a number of examples of various types of MP generators, or “pulsers”, which are familiar to those skilled in the art. U.S. Pat. No. 8,251,160 describes a rotor/stator design with windows in the rotor which align with windows in the stator. The stator also has a plurality of circular openings for flow of fluid therethrough. In a first orientation, the windows in the stator and the rotor align to create a fluid flow path orthogonal to the windows through the rotor and stator in addition to a fluid flow path through the circular openings in the stator. In this fashion the circulating fluid flows past and through the stator on its way to the drill bit without any significant obstruction to its flow. In the second orientation, the windows in the stator and the rotor do not align and there is restriction of fluid flow as the fluid only flows through the circular holes in the stator. This restriction creates a positive pressure pulse which is transmitted to the surface and decoded.
Another type of valve is a “poppet” or reciprocating pulser where the valve opens and closes against an orifice positioned axially against the drilling mud flow stream. Some have permanent magnets to keep the valve in an open position. The permanent magnet is opposed by a magnetizing coil powered by the MWD tool to release the poppet to close the valve.
Advantages of MP telemetry include increased depth capability, no dependence on earth formation, and current strong market acceptance. Disadvantages include many moving parts, difficulty with lost circulation material (LCM) usage, generally slower band rates, narrower bandwidth, and incompatibility with air/underbalanced drilling which is a growing market in North America. The latter is an issue as the signals are substantially degraded if the drilling fluid inside the drill pipe contains material quantities of gas. MP telemetry also suffers when there are low flow rates of drilling mud, as low mud flow rates may result in too low a pressure differential to produce a strong enough pulse signal at the surface. There are also a number of disadvantages of current MP generators, including limited speed of response and recovery, jamming due to accumulation of debris which reduces the range of motion of the valve, failure of the bellows seal around the servo-valve activating shaft, failure of the rotary shaft seal, failure of driveshaft components, flow erosion, fatigue, and difficulty accessing and replacing small parts.